As an oil and gas field declines—a term used to describe the natural processes that occur in a hydrocarbon field—the wellbore will “water in” and lose formation pressure. “Water-in” is another term of art to explain that formation water will enter the wellbore. The effect that “watering-in” has on the wellbore is to slowly buildup water in the wellbore. Generally, in a newly discovered field, the formation pressure will force produced liquids out of the wellbore. This is not the case when the field declines and the liquid head will eventually act to back-pressure the formation inhibiting the further production of hydrocarbon fluids from wellbore unless artificial lift techniques are employed.
In an oil field, as the formation pressure declines artificial lift techniques employing mechanical pumps (surface or downhole), cable lift (see U.S. Pat. No. 6,497,281 to the current inventor), plunger lift (which applies to gas wells), or standard gas lift (which applies to hydrocarbon fluids—oil or oil and gas plus produced water) will be employed. The standard methods work well in most wells, but as the wells really decline, are extremely deep, or if the wellbore serves multiple zones, the standard methods begin to fail or become too expensive, particularly in the case of gas production.
Marginal wells, also called stripper wells, are usually uneconomical for the major oil companies to operate because the labor and pumping costs are close to the revenue from the hydrocarbon sales. Every day many of these unprofitable stripper wells are being shut in, plugged, and abandoned. But there is a type of oil field hand that loves to get possession of these marginal wells because he has the where-with-all to scrounge up enough equipment to maintain and operate these wells at a small profit.
Many of these stripper wells in the U.S.A. produce only about 10 barrels or less, of crude oil per day or about one thousand cubic feet or less, of gas per day, depending on the type of stripper well. These wells are important to the U.S. economy, especially during times of political unrest when they become vital to our national defense. After all, just one day's production at a rate of 10 barrels, or 420 gal, of oil/day will operate a small auto several thousand miles after the crude oil has been refined into fuel. In a similar manner, a couple of thousand cubic feet of gas will heat a home for several days in mid winter.
Accordingly, it is desirable to make available novel well production equipment that is relatively inexpensive and can be assembled from mostly commercially available material and thereby increase the profit gleaned from a stripper well. Additionally, the novel equipment should be easy to work on and have low cost maintenance and operation. Further, the novel equipment should operate the well in such a manner that the production rate can be increased from marginal to profitable. When all of these and several other desirable attributes are considered, it is easy to see that they add up to a novel well production system that provides the unexpected result of changing an unprofitable situation into one that is profitable.
In the area of stripper gas production, as explained, plunger lift has been used successfully as it is reliable and inexpensive to operate; however, as the well really begins to water in and the field pressure declines, plunger lift fails. The industry has tried pumping water, but the cost becomes prohibitive. It is also interesting to note that many gas stripper wells are “multiple completion wells.” That is, one wellbore serves several production zones, and as a result there will be one or more sets of production tubing in the wellbore. If a pump jack is used in the small production tubing the sucker rods tend to wear against the tubing walls thereby causing premature failure of the tubing.
The system disclosed by the inventor in U.S. Pat. No. 6,497,281 (Cable Actuated Downhole Smart Pump) could be employed in a wellbore utilizing multiple sets of production tubing. That is to say the continuous cable—without the standard sucker rod joints—operating within the tubing would tend to minimize wear on the tubing. However, such a system would not really be economic as the use of the cable pump is only to remove water and not hydrocarbon fluids for which it was designed.
The prior art is awash with gas lift disclosures. Eris, U.S. Pat. No. 2,380,639—Production of Oil—discloses an improved gas-lift method for the pumping of high paraffin content crude oil (produced fluid) whereby the method reduces or eliminates he deposition of paraffin in the production tubing. The method disperses light hydrocarbons into the production tubing while applying standard gas-lift techniques.
McCarvell et al., U.S. Pat. No. 2,948,232—Gas Lift Methods and Apparatus—disclose a modified standard gas-lift system which uses standard gas lift valves throughout the production tubing but in conjunction with “chamber and control valves” which will impart a pressure surge to the liquid within the production tubing thereby increasing the lifting force.
Arutunoff, U.S. Pat. No. 3,138,113—Multi-stage Displacement Pump—discloses a gas driven multi-stage liquid lift pump placed in the bottom of the production tubing.
McLeod, Jr., U.S. Pat. No. 3,215,087—Gas Lift System—discloses an improved gas-lift method using a standard lift system, but wherein an immiscible fluid is regularly injected into the lifted fluid in order to reduce the tendency of the lift gas to bypass the lifted fluids.
Erickson, U.S. Pat. No. 3,522,955—Gas Lift for Liquid—discloses a unique, but potentially dangerous system for gas-lifting of produced fluids. Erickson ‘sends’ a flammable mixture of gas and air to a combustion chamber located at the distal end of the production tubing. The mixture is ignited in the chamber and the products of combustion which will be “4-6 times greater in volume” act to lift the produced hydrocarbons.
McMurry et al., U.S. Pat. No. 3,630,640—Method and Apparatus for Gas-Lift Operations in Oil Wells—discloses a unique system to protect standard gas-lift valves in a production string during the initial completion and fitting of a hydrocarbon well. The McMurry concept adds a blocking device to each gas-lift valve which remains CLOSED during the initial completion and cleaning out of the hydrocarbon well. Once the “clean-out” pressure is reduced to the operating pressure, the McMurry blocking valves OPEN (and remain open); thereby, allowing the protected gas-lift valves to operate normally.
Beard et al., U.S. Pat. No. 3,736,983—Well Pump and the Method of Pumping—disclose an air driven pumping system in which air flow is cycled to a series of alternating tanks spread throughout the production string which in turn lift the produced fluid.
Bobo, U.S. Pat. No. 4,711,306—Gas Lift System—discloses an improved gas-lift system, similar to McLeod, Jr., in which injection gas is mixed with injection fluid prior to injection into the borehole. The gas and fluid interact with the produced liquid column to lift the column thereby producing the well.
Boyle, U.S. Pat. No. 5,176,164—Flow Control Valve System—discloses an improved gas-lift system utilizing a series of standard gas lift valves located throughout the length of the production tubing with a ‘flow control valve’ located at the distal end of the production string, essentially the flow control valve is controlled (by the system) from full open to full closed permitting a controlled flow of produced fluids onto the production tubing. Standard gas lift techniques lift the fluid column within the tubing.
Kritzler et al., published U.S. patent application 2007/0181312—Barrier Orifice Valve for Gas Lift—disclose a substantially improved gas-lift valve for use in standard gas-lift systems. The improvement is a pivotable flapper valve that is highly resistant to wear and which will provide positive shutoff during the life of the improved valve.
Reitz in U.S. Pat. No. 5,911,278 discloses a “Calliope Oil Production System,” which is designed to produce oil and gas during the declining portion of the field's life. Essentially Reitz uses compressed gas, a string of “macaroni tubing” inserted inside the production tubing within the casing of the wellbore. A series of valves connect to the casing, the production tubing and the macaroni tubing. The series of valves (at least 6 to 10) are then manipulated to send compressed gas down the wellbore and suck on the system. By careful manipulation of these valves, the produced fluid is forced out of the well. In other words there are no mechanical moving parts (other than a check valve located at the bottom of the production tubing) within the wellbore.
In U.S. Pat. No. 6,672,392, Reitz addresses pure gas recovery in an improvement to his earlier disclosure. Again, the system utilizes a complex series of valves and valve operations at the surface to lift the liquid column.
What is required in the industry is a simple system and method to remove produced liquid from a wellbore which has filled with produced fluid thereby allowing gas to freely flow from the formation.
Vann addressed this need in his application “A Gas Assisted Lift System” Ser. No. 12/072,725 filed on Feb. 28, 2008 in which his invention comprised a series of normally open differential pressure controlled valves (“ΔPCV”), which are designed to be placed onto, in communication with, and attached to small tubing. (E.g., 1-inch or larger coiled tubing.) The ΔPCV's are spaced apart on the coil tubing at a given distance which is readily determined by a simple head/drive pressure formula. An eduction valve (or jet pump) is placed on the distal end of the coil tubing and the coil tubing is run into the existing production tubing which itself may be retained by a hold down or packer at the bottom of the production tubing. The eduction valve—retained by the small (or coiled) tubing—is placed just above the seating nipple.
Compressed gas is passed into the production tubing, which surrounds the smaller tubing, and passes down the larger tubing until it reaches the fluid level. At this point, the fluid level is depressed by the gas pressure and the fluid passes into the smaller tubing at the uppermost normally open ΔPCV. When the retreating fluid level reaches the uppermost valve, gas will pass through the ΔPCV thereby pushing the fluid, in the small tubing, to the surface. (Essentially the gas acts like a coffee percolator lifting the fluid to the surface.) As the fluid level in the smaller tubing drops to the same level as the uppermost ΔPCV, the uppermost valve closes and remains closed.
At this point the second valve in the string will accept liquid flow and the process repeats. This process will repeat until all the ΔPCV's are closed and the formation liquid now appears at the wellbore bottom where the eduction valve or jet pump takes over to move liquid to the surface. Produced gas from the formation is now free to flow up the one-inch tubing to the surface under formation pressure.
If the gas compressor goes down, for what ever reason, movement of produced liquid will cease and the hydrostatic head will rebuild throughout the wellbore thereby inhibiting gas production. When the compressor is brought back on line, the ΔPCV's will act to lift the liquid thereby restoring gas production.
Finally, because one of the most common problems in pumping water from gas wells is deposits of salt and scale into the orifice (⅛″ opening), the ΔPCV system is designed to allow fresh water with gas to be reversed down the smaller (lift) tubing and into the larger production tubing to remove partial plugging. Thus, any build of deposits in the system components can be reverse pumped back to the surface through the production tubing, for disposal, either manually or automatically, if the control system is set to incorporate this automatic feature.
However, as the invention was developed and field tested, improvements were invented which assured that the normally open differential pressure controlled valves (“ΔPCV”) would operate more reliably. Furthermore, in the original disclosure, the ΔPCV's were placed on the outside of the lift tube. Although, this concept worked, it was discovered that the valves would leak between the valve and the lift tube and acted as an obstruction as the lift tube was placed in a well. Thus, certain “improvements” were made to the system and the underlying mechanics of the differential pressure control valves. Finally, the inventors determined that the system was capable of lifting liquids in a well column so that the system may be used to produce oil.